MVCAC October 2021

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The life-or-death race to improve carbon capture
by DUANE NICHOLS 12 Nov '21

12 Nov '21

NOTE ~ Here is the best technical review of Carbon Capture technology that is currently available, dated July 18, 2021. It’s from an official publication of the American Chemical Society, the most trusted organization of chemistry & chemical engineering. Even so, this article is biased toward an optimistic view of current R&D as well as industrial development projects. We all know that R&D and development projects cannot in and of themselves be relied upon to be successful! Notice one of the leading sentences, “Carbon capture isn’t about saving Earth.” [Rather, radical changes in our collective life-styles must take place! Governmental actions are required to make this happen! DGN] >>> Duane G. Nichols, Ph.D., Chemical Engineer, October 5, 2021. https://cen.acs.org/environment/greenhouse-gases/capture-flue-gas-co2-emiss… The life-or-death race to improve carbon capture Chemical & Engineering News, American Chemical Society, July 18, 2021 The technology works, but we’ll need better chemistry and engineering to reach the scale required to avoid a climate disaster Carbon capture isn’t about saving Earth. Earth is a wet rock floating through space; it doesn’t care if we drown our coastal cities or turn our farmland into desert. Rather, carbon capture is one of the technologies we will need if we want Earth to continue to be a tolerable place for humans to live. In brief The carbon-capture chemistry we have today is too expensive. It works, and it makes economic sense in a few settings. But to meet the global-consensus goal of net-zero carbon dioxide emissions by 2050 and dodge the worst consequences of climate change, we need to deploy more than 150 times as much carbon-capture capacity as we have now. That means reducing costs and making more options available for a wide range of CO2 emission sources. Read on about the growing number of businesses, government labs, nonprofits, and academic researchers racing to bring the next generation of carbon-capture technology up to scale and into the market. In 2020, we sent 40 billion metric tons (t) of carbon dioxide into Earth’s atmosphere. We need to cut that number to 0 by 2050 if we are to avoid the worst consequences of climate change, according to the Intergovernmental Panel on Climate Change (IPCC). If we don’t, the natural systems that keep Earth’s climate relatively peaceful and comfortable will start to tip. The shift will be chaotic, and the new normal might not be conducive to life as we know it. To reach net-zero CO2 emissions by 2050, we need an all-of-the-above approach. Efficiency improvements can reduce our energy needs, and renewable and nuclear power may eventually be able to supply enough electricity for our homes, offices, and cars. But nuclear power is expensive and lacks public support, and renewables are struggling to find the land they need to be deployed at scale. On top of that, activities such as aviation and iron smelting are currently impossible to carry out commercially without releasing CO2. That’s where carbon capture comes in. Removing carbon dioxide from point sources such as the flue gas of power plants and locking it away underground can be a big part of the path to net zero. Related technologies known as direct air capture can remove CO2 that is already in the ambient air. But all of it depends on carbon capture getting a lot bigger, cheaper, and more efficient — and doing so quickly. Slow start Capturing the CO2 from power plants’ flue gas is where most of the action is. “Decarbonization of the power sector becomes the backbone that the decarbonization of the rest of the economy happens on,” says John Northington, director of the National Carbon Capture Center, a research facility near Birmingham, Alabama. What’s your gas stream? Different emission sources require different carbon-capture methods. Ammonia, ethanol, natural gas processing: Emit gas streams with more than 80% CO2. The CO2 is captured with compression and dehydration, membranes, or physical solvents. Chemical plants, iron, steel and paper mills: Emit gas streams with 15–80% CO2. The CO2 can be captured with physical solvents, solid sorbents, or membranes. Coal and natural gas power plants and boilers: Emit gas streams with less than 15% CO2. The CO2 can be captured with chemical solvents. Ambient air: Has a CO2 concentration around 0.041%. The CO2 can be captured with metal-organic frameworks or chemical systems. Sources: Global CCS Institute, National Petroleum Council. But just one commercial power plant has carbon capture: the coal-fired Boundary Dam Power Station in Saskatchewan, which captures 1 million t of CO2 per year on one of its four generators. Carbon capture elsewhere on other industrial processes, such as natural gas production, adds another 27 plants and gathers 25 million t per year. Not nearly enough. The people developing the technology that will make capturing carbon practical have gained unlikely allies in the past couple of years: the oil and gas companies responsible for the lion’s share of CO2 emissions. Though these firms have had their eyes on carbon capture for some time, Northington says, they’re investing serious money in it now. Data from the patent research firm Patent Seekers bear that notion out. Oil companies have gotten the largest number of carbon-capture patents in recent years, followed by government agencies and research institutes, universities, and engineering and technology companies. Klaus Lackner, an engineering professor working on direct air capture at Arizona State University, says the change in attitude is a result of pressure from two directions: competition from cheap renewable energy and public demand for low-carbon options. Major changes are coming to the energy market, Lackner says. “The question isn’t ‘Will we have a transition?’ We will. The Exxons and Shells and other companies have to figure out how to make it through that transition. Their business model falls apart if you can’t have liquid fuels.” Lackner says he’s been pushing fossil fuel companies on this point for years, telling them, “Your societal license to dump CO2 into the air will go away. You need to figure out how to operate without needing that license.” Matt Steyn, a senior adviser with the advocacy wing of the Global CCS Institute (GCCSI), a carbon-capture-and-storage think tank, says the change is also driven by the scientific consensus expressed by the IPCC and the International Energy Agency. “The target has been set; the timeline has been set,” he says. The conversation has shifted from “What do we do?” to “How do we do it?” As we deploy more plants, costs will come down, just as they have done in every other sector. Steve Oldham, CEO, Carbon Engineering Carbon capture of all types is a gas-separation problem. The goal is pure CO2, ideally at high pressure so it can go into a pipeline and be injected safely underground. For some industrial processes, the capture technology available today works fine. In ammonia and corn ethanol plants, for example, the gas exiting exhaust pipes is 80% or more CO2 and just needs to be dried and compressed for transport. As the CO2 in emissions gets more dilute, the energy required to extract it rises. The emissions coming from steel plants and many chemical processes tend to be between 15 and 80% CO2. The flue gas from fossil fuel combustion in air, such as in coal or natural gas–fired power plants, is generally less than 15% CO2. Capture with solvents Carbon dioxide–rich flue gas flows up a contact tower and mixes with a solvent that is trickling down (left). Reduced-CO₂ gas vents from the top, while CO₂-rich solvent exits at the bottom and flows to the top of a stripping tower. There, the solvent is heated, usually by steam, as it trickles down. The heat forces the CO₂ out of solution and up to a collection system. The refreshed solvent heads back to the contact tower to start again. Credit: Adapted from CO2CRC Ironically, oil companies are some of the biggest practitioners of carbon capture today because they use solvents, membranes, and other technologies to remove CO2 from natural gas deposits found in locations such as Russia and west Texas. When they use or sell that CO2 instead of venting it, that counts as carbon capture. That’s why ExxonMobil can claim to capture more CO2 than any other company, even if it uses most of that to push more oil out of the ground. Amine-based extraction systems developed for natural gas processing have been adapted for other CO2 sources, such as the power plant in Saskatchewan, but the energy cost of using such systems on more dilute streams is crushingly high. Second-generation solvent systems are poised to come to market next, followed by membranes and solid sorbents. And numerous innovative and experimental approaches are racing to catch up. Syrie Crouch, vice president for carbon capture and storage at Shell, which built the Saskatchewan plant, says deploying capture where it’s simple is an important start. US ethanol makers, for example, capture only 3 million t of the 43 million t of CO2 their plants produce each year. “The key is to capture that lowest-hanging fruit first and then work on down the cost curve,” she says. Incumbent amines The most mature carbon-capture technologies today use solvents. These systems pump emissions through a solution that absorbs CO2 but lets through other gases, such as nitrogen. The CO2-rich solvent then flows into a boiler, where heat drives the pure CO2 back out of solution. That stripping step is the energy hog. Though the terminology is harsh to a chemist’s ears, carbon-capture solvents are considered either chemical or physical. Chemical solvents, mostly amines such as the industry standard 30% monoethanolamine in water, get a CO2-solubility boost through reversible chemical reactions with water and CO2 that form carbonates, bicarbonates, and carbamates. Physical solvents such as methanol rely on intermolecular interactions to dissolve CO2. Companies including Linde, Air Products, and UOP offer such systems commercially. They use less energy than chemical solvents but require high pressures and low temperatures. They’re not suitable for combustion flue gas but have been used for many years to remove CO2 from natural gas. Almost like a filter Membranes separate gas mixtures on the basis of size or chemical properties. Some molecules can pass through, and others cannot. Credit: Adapted from CO2CRC Amine solvents have the advantage of being mature technology. The systems are well understood, with well-characterized economics and risk profiles that investors know how to analyze. Dow, Shell, Fluor, and others offer monoethanolamine solutions for carbon capture. Boundary Dam Unit 3 uses amines, as did NRG Energy’s Petra Nova plant in Texas, which captured more than 1 million t of CO2 per year from 2017 until NRG shut it down in 2020. BASF, Linde, General Electric, and the start-up Carbon Clean are among those working on advanced amines. These systems use chemicals such as piperazine alongside or instead of monoethanolamine to get better stability, kinetics, and thermodynamics. The US Department of Energy recently awarded Linde and the University of Illinois at Urbana-Champaign $47 million to build a 200 t per day pilot facility using an advanced amine solvent from BASF at a coal-fired power plant near Springfield, Illinois. But capturing CO2 with amines comes at a steep cost. Fitted onto a power plant’s systems, they consume 30–50% of the plant’s energy output. Most experts, including Shell’s Crouch, expect that amine systems can get only 10–20% more efficient. At the same time, amines can seem like a safe bet compared with a next-generation technology. “If you’re making your first investment in carbon capture and storage, you don’t necessarily want to be taking massive risks on something new and untested,” the GCCSI’s Steyn says. The next generation At the National Carbon Capture Center (NCCC) and the Wyoming Integrated Test Center (ITC), two next-generation carbon-capture technologies that look promising are solid sorbents and membranes. CO2 Solutions, now part of Saipem, engineered carbonic anhydrase to fit the demands of carbon capture. The NCCC and ITC sites are essentially coal-fired power plants that can pipe their flue gas into a series of testing bays. The NCCC tests systems at scales from less than 1 t per day up to about 25 t per day; tests at the ITC run between 25 and 450 t per day. The sites, which use a combination of public and private financing, serve as technology development bridges between lab-scale carbon-capture concepts and pilot-scale tests on commercial power plants. The NCCC’s Northington says the incumbent amine systems can capture carbon at a cost of $60–$65 per metric ton. Advanced amines and other second-generation solvents are about $40 per metric ton. A handful of commercial installations that will use advanced amines are in early-stage engineering now, he says. Solid sorbents, membranes, and other transformational technologies will reach $30 or less per metric ton, he predicts. “We want choice in the marketplace,” says William Morris, technical director of the ITC. “People are really trying to figure out what works for them, not only in their industry but in their specific circumstance.” Solid sorbents include zeolites, metal-organic frameworks (MOFs), activated carbon, and porous silica particles. They’re often functionalized with amine groups to increase their activity and make them more selective for CO2. Merry-go-round In Svante's solid-sorbent capture system, flue gas first flows down (left) through a rotating disk loaded with a sorbent material that removes the carbon dioxide. At the next station (right), steam flows through the sorbent, stripping the now-pure CO2 out for collection. A third station (rear) refreshes the sorbent on the way back around to the flue gas station. Generally, solid sorbents have faster absorption kinetics than amines and require less energy to release the CO2 again. They can also hold more CO2 per unit volume than most solvents. That means that solid-sorbent systems can be smaller, reducing capital costs, and can be stripped of their CO2 using vacuum or modest heat. The start-up Svante forms solid sorbents into large, nanoporous disks divided into slices like a pizza. On a giant turntable, the disk slowly rotates each slice through a flue gas stream, a CO2-stripping module, and one or two sorbent preparation stations. The firm has a 10,000 t per year demonstration plant on a natural gas–fired boiler in Canada. It raised $75 million in February to advance a design for cement plants. In addition to Svante, ExxonMobil, Kawasaki Heavy Industries, TDA Research, and others are testing solid-sorbent systems for flue gas capture. Shell, which is shifting its R&D to solid sorbents, tested a system that uses amine-functionalized solid sorbents on a wood-burning power plant in Austria; it is now readying a scaled-up test at a manure-to-power plant in the Netherlands. After these trials, Crouch says, Shell will offer the technology on the open market. Membranes are even further along than solid sorbents, Morris says. Membrane systems use selectively permeable materials that exploit the small chemical and physical differences between CO2 and the rest of a gas mixture to achieve separation. Like amines, membranes are already being used in natural gas processing and other areas where CO2 pressure and content are high. “The next technology outside of amines that will deploy will be membranes,” Morris predicts. He says membranes are coming fast for capturing CO2 from flue gas at power plants. And Northington expects membranes will play a big role in carbon capture for the chemical industry and heavy manufacturing, which have moderate to high CO2 concentrations. Getting any new carbon capture technology to market won’t be cheap. Morris says getting a robust set of data from testing at the ITC can cost seven figures. One membrane maker, Membrane Technology and Research (MTR), won $52 million in funding in May from the US Department of Energy to do just that. MTR ran a 20 t per day version of its system for 1,400 h at the NCCC in 2015 and will use the funds to scale it up to 150 t per day in Wyoming. The company expects to demonstrate capture at less than $40 per metric ton. MTR’s membrane polymers are isoporous, meaning their pores are uniform in size and arranged geometrically, unlike the randomly arranged, multisize pores in most gas-separation membranes. The regular pore pattern lets molecules flow more smoothly through the material, lowering the amount of pressure needed relative to conventional membranes. And a tighter distribution of pore sizes increases selectivity for CO2. Another membrane maker, Compact Membrane Systems (CMS), also seeks to decrease costs by reducing pressure. CMS uses facilitated transport membranes, which are specialized fluoropolymers coated onto a porous substrate. CEO Erica Nemser likens the mechanism to Tarzan swinging through the jungle on vines. The CO2 is Tarzan, and fluoropolymers decorated with activating groups act as the vines, passing CO2 along, with minimal pressure needed. The firm’s systems are already being used to separate olefins from paraffins and to remove water and dissolved gases from solvents, oils, and lubricants. The system that will capture CO2 in flue gas will be a modification of one that’s in field trials now for removing CO2 from biomethane. Chemical changes to the fluoropolymer make the membrane selective toward different chemical species, Nemser says. CMS’s units are built around membrane cartridges about twice the size of a can of spray paint—hence the “compact” in the company’s name. The bigger the gas stream to be treated, the more cartridges the system uses. Chief Technology Officer Hannah Murnen says such modular systems will make carbon capture accessible for a wide range of CO2 point sources. In contrast, the towers needed to mix amine solvents with a gas stream and strip the CO2 out later make economic sense only at enormous scales, she says. CMS says it will be able to deliver carbon capture for as little as $20 per metric ton. “It’s time for membranes. It’s membranes’ day in the sun,” Murnen says. Tomorrow’s tech Amines may dominate carbon capture today, and membranes and solid sorbents may be right on their heels, but a need this serious—and a market this big—is attracting plenty of other contenders. And a good-enough concept could leap ahead if the people behind it can show it works and is scalable. Saipem and Chart Industries both hope to adapt technology and equipment already in use in other chemical processes. In January 2020, Saipem, an energy technology and engineering firm, acquired CO2 Solutions, a start-up that is using enzymes to boost the carbon-capture kinetics of aqueous potassium carbonate. K2CO3 reacts with CO2 and water to form potassium bicarbonate, KHCO3. The bicarbonate solution releases its CO2 at relatively low temperatures—around 75 °C under reduced pressure—meaning it can tap low-grade heat that most industrial processes would waste. That chemistry has been used to scrub CO2 from the air in submarines and other closed environments and in some high-CO2-concentration settings. The trouble is that the absorption kinetics are too slow for it to work well at flue gas concentrations and pressures; the contact towers would have to be even bigger than those used with amines. To solve that problem, Saipem catalyzes the reaction with the enzyme carbonic anhydrase. Natural carbonic anhydrase is already one of the fastest enzymes, speeding up the formation of HCO3– by a factor of 107. The team at CO2 Solutions modified the enzyme to make it even faster and keep it active at higher temperatures. “The first time I saw carbon capture with the enzyme, my jaw just dropped, because the catalyst is magic,” says Richard Surprenant, who came to Saipem from CO2 Solutions and is now commercial manager for carbon-capture technologies. Any industrial or postcombustion application is fair game for the firm’s technology, Surprenant says, and anywhere with low-grade waste or geothermal heat is an opportunity, because it doesn’t need the high-grade heat, a resource many plants already use in other ways. The firm is in the midst of restarting CO2 Solutions’ first commercial plant, a 30 t per day facility in Quebec that extracts CO2 from a paper mill and sells it to a nearby greenhouse. Chart Industries, an energy and industrial gas equipment firm, is also moving into carbon capture through acquisition and investment. In late 2020, Chart acquired Sustainable Energy Solutions, a start-up making cryogenic carbon-capture systems for combustion flue gas. In June of this year, it invested in Earthly Labs, which uses cryogenics to capture CO2 from breweries. Credit: Mosaic Materials Mosaic Materials' carbon-capturing metal-organic frameworks. In the simplest terms, both cryogenic systems chill their target gas streams until the CO2 condenses into a solid or liquid. Nitrogen, still a gas at those temperatures, is pumped off. The basic process, often called cryogenic distillation, is already used to purify other industrial gases, such as oxygen and nitrogen. The challenge for flue gas is in the engineering, not the chemistry, according to Chart CEO Jill Evanko. If water and CO2 freeze in the wrong places, they can clog pipes and block heat exchangers. But with clever heat management, system design, and integration with the rest of the equipment, Chart and its partners can deliver carbon capture of flue gas at half the cost of conventional amines, Evanko says, and make brewery carbon capture profitable enough to pay off the equipment in 18 months. Several other technologies are in early-stage development. Solvents that use less water or no water at all, including organic solvents and ionic liquids, could reduce the amount of mass that needs to be heated to release the purified CO2. Allam cycle power plants burn hydrocarbons in a mix of O2 and CO2, sidestepping the need to separate CO2 from nitrogen. And FuelCell Energy is commercializing its molten carbonate fuel cell, which can capture flue gas carbon while generating additional electricity from natural gas. It’s an exciting time for technology development, the ITC’s Morris says. “Decarbonization is going to be very, very difficult, and it’s probably not going to be possible without technologies that are currently in the development stage.” State of play Carbon capture is in its early days, especially for combustion flue gas, such as the emissions of a coal-fired power plant. Researchers are working on each of the technologies below to make them cheaper and more efficient and to get them to work on a wider variety of gas streams. A single commercial-scale installation could let a new technology pass its competitors or even take the lead. Sources: Global CCS Institute, National Petroleum Council, International Energy Agency, C&EN reporting. Direct air capture Point-source carbon capture won’t be enough. The technology still lets 2–10% of the carbon through. And it’s hard to deploy on sources with diffuse or mobile emissions, such as airplanes, sprawling petrochemical plants, and wide-open wastewater treatment facilities. Besides, the atmosphere has too much carbon already. The goal of net-zero CO2 emissions will require methods to remove carbon from the air. This direct air capture, or DAC, works on chemical principles similar to those for point-source capture. The big difference is that our ambient air, although overloaded, is still only 410 ppm, or 0.041%, CO2, much lower than even the most dilute industrial point sources. And that changes a lot about the devices and their economics. Because flue gas and other point sources are releasing new carbon into the atmosphere, the goal is to capture as much of it as possible—90% is a common target. In DAC, the amount of carbon left behind isn’t important; it’s all about how much CO2 can be removed per dollar spent. “My goal is not to make CO2-free air. My goal is to take CO2 out of the air, and I can choose where the optimal efficiency is,” says Lackner, the Arizona State engineer, who is also developing DAC technology. But however you look at it, DAC is expensive. Carbon capture at an ethanol plant can cost as little as $10 per metric ton. At a coal-fired power plant, the cost is around $60. DAC companies don’t like to talk about their costs, but industry insiders estimate they are around $500 per metric ton. Lackner and other experts generally peg $100 as the point at which DAC will become cost competitive with other decarbonization methods. Oxy Low Carbon Ventures, a carbon-reduction subsidiary of Occidental Petroleum, thinks it can reach that level in partnership with the start-up Carbon Engineering. The firms plan to build in the southwestern US what they say will be the world’s first commercial-scale DAC plant. It will capture 1 million t of CO2 per year, to be used mainly to boost production in Occidental’s oil wells in the region. The largest existing DAC plant captures a mere 2,000 t per year, according to Ryan Edwards, low-carbon policy adviser for Oxy Low Carbon. Carbon Engineering uses chemical looping to capture carbon from the air. In its process, intended to run on renewable energy, giant fans blow air over plastic surfaces that have aqueous potassium hydroxide flowing over it. The KOH reacts with CO2 to form potassium carbonate, K2CO3, which then flows into a pellet reactor containing aqueous calcium hydroxide, Ca(OH)2. The calcium and potassium switch places to form CaCO3, which precipitates out as solid pellets, as well as KOH, which is ready to cycle back to the plastic surfaces. The pellets then pass into a calciner, a heater that decomposes the CaCO3 into solid CaO and pure CO2. The CO2 is cooled and pressurized, and the CaO heads back to the pellet reactor, where it mixes with water and re-forms Ca(OH)2. The system sounds complicated, but it’s built mostly out of reactions and equipment already in use in industry. The pellet reactor is adapted from papermaking. Calciners running the same chemical reaction are central to cement production, and other versions come into play in glass, uranium, petroleum coke, and gypsum processing. The Dry Fork power station in Wyoming sends some of its flue gas to the Wyoming Integrated Test Center, where users test new carbon-capture technologies. Carbon Engineering published its process in 2018, projecting costs between $94 and $232 per metric ton (Joule, DOI: 10.1016/j.joule.2018.05.006). CEO Steve Oldham says the firm is “extremely confident” its costs will be in that range and expects that second and third generations will ensure a cost of $100 or less. “As we deploy more plants, costs will come down, just as they have done in every other sector,” Oldham says. Mosaic Materials, a developer of MOFs and one of C&EN’s 10 Start-Ups to Watch in 2019, pivoted to DAC from point-source capture 2 years ago, according to CEO Thomas McDonald. In the past 3 months, McDonald says, he’s seen a sharp increase in interest in DAC. The firm’s MOFs use a flavor of CO2-amine chemistry that McDonald calls cooperative binding, in which the CO2 inserts itself between a magnesium ion and an amine ligand. The mechanism gives the material high capacity and fast kinetics, and it reverses at relatively low temperatures to release the CO2, according to McDonald. MOFs are more expensive than other solid sorbents such as silica or activated carbon. Mosaic researchers are working to improve the materials’ capacity and stability to reduce operating costs, McDonald says. But the firm is focused more on lowering manufacturing costs and optimizing complete systems around its materials. Mosaic worked with ExxonMobil on flue gas capture in 2017 and 2018 and has some ongoing work in that area, along with collaborations with NASA and the US Navy on life-support systems, McDonald says. But he sees DAC as the best way to build his company. “We see the fastest, least-capital-intensive, least-risky path is by achieving early scale on projects through direct air capture.” We will require something roughly the size of the current oil and gas industry, but with the molecules going in reverse. Syrie Crouch, vice president for carbon capture and storage, Shell Lackner says DAC is a good fit with renewable energy. If a natural gas power plant is off because of low demand, so is any point-source carbon-capture device attached to it. DAC, on the other hand, can run on renewable energy and stabilize electricity prices by being a customer of last resort. In addition to his academic work, Lackner is working to commercialize his own DAC concept, which he calls MechanicalTrees. The “trees” eliminate the cost of running fans by relying on wind to move air across sorbents loaded onto disks arranged in a tower. When saturated with CO2, the towers drop into a chamber where heat and vacuum remove the CO2 at roughly 95% concentration. Paying for it All cool ideas, but who’s putting up the cash? A provision of the US tax code called 45Q offers tax credits for capturing carbon. When the provision is fully in place in 2026, carbon that is captured and sequestered will be worth $50 per metric ton. CO2 used to extract more hydrocarbons, a widespread and controversial practice called enhanced oil recovery, gets $35. That $35 credit plus the $40 per metric ton that enhanced oil recovery operators pay for CO2 on average make that market the most profitable for non-food-grade CO2, even with the lower credit (Front. Clim. 2019, DOI: 10.3389/fclim.2019.00005). That makes the economic rationale for carbon-capture products dependent on the price of oil. That dynamic is what doomed the Petra Nova carbon-capture facility when the price of oil got too low during the pandemic. Still, Oxy Low Carbon executives are prepared to depend on enhanced oil recovery for their southwestern US DAC project. Despite such bumps, carbon capture offers a way to decarbonize combustion and other CO2-emitting processes so they can remain part of a net-zero world. That’s both a selling point and a point of criticism. Critics such as Greenpeace say carbon capture diverts resources away from renewables and keeps polluters in business. Your societal license to dump CO2 into the air will go away. You need to figure out how to operate without needing that license. Klaus Lackner, engineer, Arizona State University Critics also point out that almost all the CO2 captured to date has been used in enhanced oil recovery. In the best cases, enough CO2 stays permanently in the ground after such oil extraction that the resulting fuel has net-negative CO2 emissions. But many enhanced oil recovery projects don’t meet that goal (Energies 2019, DOI: 10.3390/en12030448). “To put it very brutally, in the beginning, I don’t care” where the captured CO2 goes, Lackner says. The technology needs to start scaling up now. He points to a recent report from the International Energy Agency detailing a path to net zero by 2050. In that scenario, point-source capture has to scale up from about 40 million t per year today to 6.6 billion t in 2050, and DAC has to grow from a few thousand metric tons per year to almost 1 billion t in 2050. If enhanced oil recovery operators are willing to be early adopters that get carbon capture down to a cost that the market will bear, Lackner says, that’ll have to do. “The only way you get there is by learning. Most industries gain 10–20% in cost reduction for every doubling of cumulative output,” he says. “If we follow normal learning curves, I’m allowed to be optimistic. If it turns out we derail from that, the sooner we know, the better off we are.” Shell’s Crouch agrees that industry needs to start deploying carbon capture now to reach the necessary scale. “We will require something roughly the size of the current oil and gas industry, but with the molecules going in reverse,” she says. Building all those plants will cost $655 billion to $1,280 billion over the next 3 decades, according to a recent analysis by the GCCSI. That’s a lot of money, but Brad Page, CEO of the GCCSI, points out in a press release that “investing around one trillion dollars over almost 30 years is well within the capacity of the private sector which invested almost two trillion dollars in the energy sector in 2018 alone. Government decisions hold the key to enabling the requisite private sector capital being allocated for [carbon capture and storage] deployment.” One proposal the US Congress is considering now would add a higher credit for carbon captured from the air. The idea has broad bipartisan support, according to Oxy Low Carbon’s Edwards. At a recent panel discussion hosted by the nonprofit OurEnergyPolicy, he expressed confidence that enhanced incentives, R&D and deployment support, and funding for infrastructure for CO2 transport and storage could all become law in the current session of Congress. Jeremy Harrell, the managing director for policy at the energy-transition nonprofit ClearPath and another OurEnergyPolicy panelist, said he expects the Biden administration to launch a 50:50 cost-sharing initiative to deploy a first wave of carbon-capture facilities. “We think that sends a really important market signal to the private sector as they look to invest in these technologies,” he said at the event. “The politics here are going to play out well over the next 18 months, and people should stay tuned.” The administration’s proposed budget for the next fiscal year includes a 61% increase in spending at the Department of Energy on carbon capture, use, and storage, though the $368 million total is far short of what many climate activists would like to see. Edwards says 45Q has opened the door to commercial-scale carbon-capture projects. Since Congress extended 45Q in 2018 and removed the cap on the number of credits available, 30 to 40 new projects have been publicly proposed, he says, which would more than double the global number. Between projects that are being kept quiet for now and new ones that will be unlocked if Congress expands 45Q, that increase is “just the tip of the iceberg,” Edwards says. It’ll need to be. Right now, 28 point-source capture and DAC plants are active, including at Boundary Dam and nonpower installations, according to the GCCSI. The world will need 2,000 large facilities by 2050, along with transportation and storage infrastructure, to reach net zero by then. “The reality is, we’ve only got a certain amount of time left,” the GCCSI’s Steyn says. “We’re now pushing against the clock.” Considering how long it takes to finance, engineer, and build a trillion dollars of industrial equipment, he says, “If you’re going to actually make inroads toward net-zero 2050, it’s got to happen this decade. This is the make-or-break decade.” Chemical & Engineering News, ISSN 0009-2347 Copyright © 2021 American Chemical Society

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Katharine Hayhoe – “Our future is still in our hands” | The On Being Project, NPR
by DUANE NICHOLS 25 Oct '21

25 Oct '21

“Our future is still in our hands” — ‘On Being Program’ — National Public Radio, October 15, 2021 Saving Us: A Climate Scientist's Case for Hope and Healing in a Divided World Author: Katharine Hayhoe, Professor @ Texas Tech University https://onbeing.org/programs/katharine-hayhoe-our-future-is-still-in-our-ha…

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EJSCREEN: Environmental Justice Screening and Mapping Tool | US EPA
by DUANE NICHOLS 22 Oct '21

22 Oct '21

I want to encourage the WV DEP to use the EJSCREEN on the Longview I and II (and other) projects. It is unacceptable to place three large power plant in Monongalia County. The people of the Ft. Martin community are the most vulnerable plus all of Maidsville. The people on Bakers Ridge are in direct line for air impacts as with my Forks of Cheat Forest, the new Summit expansive development, etc. University High School is VERY close. Realize we have elder care facilities all over this region, not to mention Heritage Point. People are coming to Morgantown from all over West Virginia for their last and best medical treatment, yet our air is already degraded and could get worse. In the typical summer camping season, the Emma Camp has over 300 young campers from all over the east coast participating in active recreation and educational programs. The role of fine particulates in combination with all the other hazardous compounds is still being investigated, but we already know that through the lungs these affect the heart and brain. Free radical chemistry is hardly known to the public or legislators or regulators, but its role is significant where we have these large coal-fired units, given the complexity of the “coal molecule.” Our residents already qualify for environmental justice relief even without another power plant. What are they thinking, those out of state developers & investors? The 300 coal trucks laboring up the Ft. Martin hill every day after day, with diesel exhausts, road damages, aggravating noises — maybe that’s why Longview thinks they have found “clean energy” ....? On Labor Day, one Ft. Martin family decided to sit out on the front porch, but were driving back inside by the diesel truck noise! Even our Monongalia County Commission looks at Ft. Martin as a mined out sacrifice zone. See the EPA EJ Screen here: https://www.epa.gov/ejscreen >>>>>>>>……………………>>>>>>>>……………………>>>>>>> LONGVIEW-HEARING- CHARLESTON GAZETTE 22 OCTOBER 2021 Job hopes, environmental fears highlighted at DEP public comment hearing on air quality permit for Mon County gas-fired plant • By Mike Tony mtony(a)hdmediallc.com Feedback was divided between welcoming potential economic benefits and decrying feared environmental perils at a public comment meeting on a proposed air quality permit for a natural gas-fired power plant in Monongalia County. The West Virginia Department of Environmental Protection held the meeting virtually Tuesday evening on the permit requested by Longview Power’s Mountain State Clean Energy LLC for the facility planned to be located immediately north of the Longview coal-fired plant in Maidsville. The project is slated to be a gas-fired, combined-cycle plant that will supply electricity to the power grid, linking to it via an interconnection used by the coal-fired plant. The West Virginia Division of Air Quality’s preliminary evaluation found that the project as proposed will meet all applicable state rules and federal regulations, prompting the division’s preliminary determination to approve the air quality application. Area union officials pushed state environmental regulators to keep leaning in that direction. They argue that constructing the plant would create critical jobs for their members. “[T]he job opportunities [are] huge. I would like to add that the jobs created will be good-paying jobs, with important retirement and health care benefits,” said Natalie Stone, representative of the Morgantown-based North Central West Virginia Building Trades Council. The proposed gas-fired plant is projected to emit 5.13 million tons of greenhouse gases, 321 tons of nitrogen oxide, 276 tons of carbon monoxide and 210 tons of particulate matter per year, according to a permit application prepared for the DEP by Ambient Air Quality Services Inc., a Pennsylvania-based air quality consulting firm. Opponents of the project objected to what they said were troubling discrepancies and inadequate air quality protection measures in the proposed permit as well as the project’s proposed greenhouse climate emissions that would contribute to the climate crisis. The International Energy Agency, an intergovernmental organization consisting of 30 member countries, said in May that investors should not fund any new coal, oil or natural gas projects if the world is to reach net zero carbon dioxide emissions by 2050. Earth must meet the mid-century deadline to limit the rise in global temperatures to 1.5 degrees Celsius and avert the worst effects of climate change, the agency reiterated in a road map for the global energy sector that included the new recommendation to end all new fossil fuel projects. James Kotcon, chairman of the West Virginia chapter of the Sierra Club’s conservation committee, observed that a draft permit for the facility lists the facility’s total electrical generating capacity as 1,300 megawatts, while a DEP preliminary determination and fact sheet for the facility notes that the facility’s electricity generation capability is 1,200 megawatts. DEP spokesman Terry Fletcher indicated after the meeting that the figure was an approximate value, adding that the output will vary based on power efficiencies and operating conditions. A PowerPoint presentation that Division of Air Quality engineer Edward Andrews showed describing the project indicated that the plant would be a 1,200-megawatt facility. Area resident Duane Nichols argued that it would be environmentally unjust for the plant to be located near West Virginia University medical facilities, health centers and other sites of importance. Two facilities Nichols mentioned, the WVU Eye Institute and Mountaineer Field, are roughly 10 miles away from the proposed facility location. “You can’t find a worse location in the entire state of West Virginia,” Nichols contended. Those anticipated emission levels are all well above federal significance levels, subjecting the plant to U.S. Environmental Protection Agency Prevention of Significant Deterioration regulations. That designation requires installation of emissions-limitation technology, air quality analysis, an additional impacts analysis assessing the effects of air, ground and water pollution, as well as public comment on permits and citizen enforcement actions against sources not complying with their permits. Project opponents questioned the “clean energy” part of Mountain State Clean Energy’s name during the meeting. “When I see a company that calls themselves Mountain State Clean Energy and then ask for 5 million tons of greenhouse gas [emissions], who do they think they’re fooling?” Kotcon asked. Mountain State Clean Energy will need to apply for a water pollution permit for the site or modify an existing one to include the new gas-fired turbine, Fletcher said. Located 3,000 feet west of the Monongahela River, the site is slated to operate two pipeline-gas compressor units. The application indicates that no greenhouse gas emissions will be associated with starting up, shutting down or operating the units. The proposed start-up date for the facility is Jan. 1, 2025, according to the DEP. Mountain State Clean Energy LLC formally changed its name from Longview Power II LLC in November. That name change came seven months after the West Virginia Public Service Commission issued a certificate to the company to construct and operate the gas-fired facility and a 70-megawatt utility-scale solar facility — 20 megawatts to be located in West Virginia and 50 megawatts in Pennsylvania. The commission also approved construction and installation of a 500-kilovolt electric transmission line extending approximately three quarters of a mile north from the gas-fired facility. Longview Power II LLC and Longview Renewable Power LLC, a separate company granted the solar siting certificate that subsequently changed its name to Mountain State Renewables LLC, estimated that the cost to construct the gas-fired facility would be $1.1 billion, according to the Public Service Commission. The Monongalia County Commission approved a 30-year, $58 million payment-in-lieu-of-taxes agreement with the Longview parties in December 2020. The Division of Air Quality will take public comments until Mon., Nov. 1 at 5 p.m. and subsequently take final action on the application. Written comments may be emailed to Edward.S.Andrews(a)wv.gov, with “Mountain State Clean Energy Comments” in the subject line, or mailed to Edward Andrews, WV Department of Environmental Protection, Division of Air Quality, 601 57th Street, SE, Charleston, WV 25304. Additional information on the project proposal can be found at https://dep.wv.gov/daq/permitting/Pages/NSR-Permit-Applications.aspx. Mike Tony covers energy and the environment. He can be reached at 304-348-1236 or mtony@hdmediallc .com. Follow @Mike__Tony on Twitter. URL:https://www.wvgazettemail.com/news/energy_and_environment/job-hopes-env…

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The Real Cost Of Joe Manchin’s Opposition To More Aggressive Climate Action
by DUANE NICHOLS 21 Oct '21

21 Oct '21

https://www.forbes.com/sites/kensilverstein/2021/10/20/the-real-cost-of-joe… The Real Cost Of Joe Manchin’s Opposition To More Aggressive Climate Action From an Article by Ken Silverstein, Forbes Magazine, October 20, 2021 Just about a year ago, a company that builds natural gas plants wanted to construct a 920-megawatt merchant facility in West Virginia. But it scrapped the project that sells its output on the open market and not at prices determined by utility regulators. That’s because it was up against coal, which controls the state capitol and which does not want competing energy forms displacing coal units. In the end, Energy Solutions Consortium said it would not pursue a previously authorized $5.6-million loan guarantee from the West Virginia Economic Development Authority. Make no mistake: not even natural gas can seep into the veins of West Virginia politicians like coal can — even though the state is sitting on top of the rich Marcellus Shale basin. Sure, coal companies are fine with permitting new natural gas pipelines that feed out-of-state facilities. But they are not Okay with building more efficient combined-cycle natural gas plants in the state. This example underscores the mindset of Senator Joe Manchin, D-WV, who is the chair of the Senate Energy and Natural Resources Committee — one of two senators holding up President Biden’s economic agenda that has a climate focus. Simply, the senator says that the transition to cleaner-burning fuels is already happening and that artificially facilitating that evolution is expensive and unnecessary. But West Virginia is also the nation’s second-largest producer of coal behind Wyoming. “Thanks to Joe, this is where we are,” says Jamie Van Nostrand, the director of the Center for Energy & Sustainable Development at West Virginia University’s College of Law as well as a lawyer appearing before utility regulators. “This is not just hurting West Virginia,” he told this writer. “It is sinking the whole climate agreement and our ability to reduce CO2 emissions. He’s trapped by a handful of coal-burning utilities and it has global implications. It is shameful.” The energy center analyzed President Biden’s Build Back Better program in the context of its potential effect on the West Virginia economy. If the state generated 80% of its electricity from sustainable fuels such as wind and solar, it would save customers a ton of money: $855 million through 2040. And it would increase employment by 3,500 jobs while growing earnings by $172 million annually. And billions would be invested in newer and cleaner power plants that would increase the state’s gross domestic product by $322 million annually. Meantime, air quality would improve while modern businesses would find the state’s natural environment enticing. The Least-Cost Path Coal generates 89% of West Virginia’s electricity. Natural gas makes up 2% of the state’s energy mix. Director Van Nostrand studied the state’s electricity rates from 2008 through 2018. He found that they rose at five-times the nationalHe points specifically to a recent West Virginia Public Service Commission ruling that allows American Electric Power’s three existing coal-fired units to keep operating through 2040. It’s not only dirtier than replacing them. It’s also more expensive — an option that will cost the utility $448 million in mandatory federal upgrades. That means utility customers will be paying 3.3% more in 2022. If the plants are retired in 2028, AEP says it would save ratepayers $28 million a year. So why not build natural gas units in their place? Or wind and solar plants? Or retrofit buildings to become more energy efficient? Coal now employs 13,000 miners — a far cry from the 100,000 it once did in 1950. Yes, market forces have displaced part of the workforce. But mechanization and automation have done the heavy lifting. With just 3% of the state’s employment tied to coal, why the outsized influence? Coal companies still pay property taxes and remain a vital part of the state’s tax base. “The key message is that a clean energy path produces more jobs, lower electricity prices, and obviously a cleaner environment for West Virginians,” says Van Nostrand. “But we are on a coal path. And we are getting pounded because of it. Our utilities have not diversified into natural gas or renewables. Let’s take advantage of the huge drop in prices for solar and wind. There is a least-cost path and there is a coal path — one that has quintupled in price.” Coal’s real costs are “externalized” and not reflected in the price of electricity. That is, there are environmental and medical costs borne by taxpayers. Abandoned mines, for example, will cost billions to repair — if they are cleaned up at all. The University of California at Berkeley says that, nationally, shedding coal would prevent $1.7 trillion in health and environmental damages through 2050. It also says that the United States can generate 80% of its power from renewables in 2030 without causing electricity prices to rise. That is because the price of wind and solar power is dropping precipitously — not to mention the cost of battery storage technologies. The Burial What is the clean energy standard that the Biden Administration wants to enact? It loosely defines clean energy as anything that either produces no CO2 or that can capture carbon and bury it. Electric utilities would need to produce a set amount of emissions-free power. Power companies that hit certain milestones would be given a payment — an incentive to increase their wind and solar production. The goal is to generate 80% clean electricity by 2030 and 100% by 2035. To get Manchin on board, this standard would be eliminated from the package. However, his Democratic colleagues would toss in billions to accelerate this country’s carbon capture and sequestration technologies. Is that smart? It depends on one’s point of view. On the one hand, coal is still expected to make up at least 30% of the global energy pie going forward, says the World Coal Association. And it does make sense to try and capture and bury CO2. On the other hand, Southern Company just destroyed its much-touted 582-megawatt Kemper plant in Mississippi that cost $7.5 billion. (It was originally forecast to cost $2.9 billion in 2006.) Even American Electric Power ditched its plans to build a carbon capture and sequestration facility in West Virginia while the FutureGen 2 was halted in Illinois in 2015 because of high costs and technological hoops. But does the recent spike in natural gas prices show that there is a place for coal? Coal use is expected to rise over the next year because of that volatility. “No one will build a coal plant based on current natural gas prices,” says Van Nostrand. “The price increase is likely to be temporary and it is predicated on supply chain issues and a rise in demand because of the pandemic. Moreover, they keep saying that carbon capture and sequestration is always on the edge of a breakthrough. That is BS. Not even close. Coal is already out of the money. Then add on the cost of underground pipelines and the cost to sequester CO2.” Consider the latest data from the U.S. Energy Information Administration: Between 2019 and 2020, coal-fired power fell by 20%. Meanwhile, renewables, including small-scale solar, increased by 9%. Wind, which it says is the most prevalent source of renewable electricity in the United States, grew 14% between 2019 and 2020. Nearly 40,000 megawatts of new capacity is expected to come online in 2021, adds S&P Global Platts. About 80% of that will be renewables. New Perspective What’s next? In an ideal world, the best way to minimize carbon emissions is to tax them. Companies would naturally migrate to lower-carbon alternatives. And if CO2 releases could be captured, investors would take a chance on it. But we all know that, politically, a carbon tax is even harder to enact than a clean energy standard — something that can be done through the budgetary process and that requires just 50 yes votes. And it won’t win Senator Manchin’s vote, whose most recent filings show that fossil fuel interests are filling his campaign chest. Still, there is an array of hope — at least within the state legislature: it has eased the path to more solar energy deployment and development, which could become viable enterprises in formerly coal-occupied areas. “There has to be a sense of urgency,” says Van Nostrand. “Utilities are not doing this fast enough. They are making the clean energy transition — just not fast enough, which undercuts Manchin’s argument that the free market is working. Biden needs to go to COP26 in Glasgow with something that is a law — a statute that can’t be reversed if another Trump-like figure emerges.” The preponderance of global citizens favors climate action. And so do most Americans. The effects of global warming are being felt today — even in West Virginia where flash floods ravaged parts of the state in 2016. Moreover, businesses are demanding action: it is not just tech companies like Microsoft, Apple, and Amazon that won’t locate to places without clean energy access. It’s also Proctor & Gamble, Target, and Toyota that are active in the fight. Joe Manchin is in his 70s. He needs to look past the next election cycle and into the future of his grandchildren. He needs to re-evaluate his positions and whether he is preventing both West Virginia and the country-at-large from getting ahead. Xxx

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Longview II Power Plant (aka Mountain State Clean Energy, no kidding?)
by DUANE NICHOLS 19 Oct '21

19 Oct '21

Public hearing scheduled for Longview gas-fired expansion POSTED BY MIKENOLTING ON OCTOBER 19, 2021 IN LOCAL NEWS MAIDSVILLE, W.Va. – The West Virginia Department of Environmental Protection will hold a virtual meeting tonight at 6 to accept public comment on an air quality permit for a natural gas-fired power plant in Monongalia County. The proposed gas-fired plant is projected to emit 5.13 million tons of greenhouse gases, 321 tons of nitrogen oxide, 276 tons of carbon monoxide and 210 tons of particulate matter per year, according to a permit application prepared for the DEP by Ambient Air Quality Services Inc., a Pennsylvania-based air quality consulting firm. Those anticipated emission levels are all well above federal significance levels, subjecting the plant to U.S. Environmental Protection Agency Prevention of Significant Deterioration regulations. That designation requires installation of emissions-limitation technology, air quality analysis to assess the effects of air, ground and water pollution. The two pipeline-gas compressor units would be located 3,000 feet west of the Monongahela River. The application indicates that no greenhouse gas emissions will be associated with starting up, shutting down or operating the units. The proposed start-up date for the facility is Jan. 1, 2025, according to the DEP. The estimated cost of the project is $1.1 billion, according to the Public Service Commission. The Monongalia County Commission approved a 30-year, $58 million payment in lieu of taxes agreement with the Longview parties in December 2020. The agency said written comments on the proposal must be received by Nov. 1. Written comments may be emailed to Edward.S.Andrews(a)wv.gov, with “Mountain State Clean Energy Comments” in the subject line, or mailed to Edward Andrews, WV Department of Environmental Protection, Division of Air Quality, 601 57th Street, SE, Charleston, WV 25304. For more information click below. (NOTE: The GHG and vapor plumes are excessive.) https://dep.wv.gov/daq/permitting/Documents/Longview%20PSD/Public%20Meeting…

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West Virginia PSC Approves Continued Operation of Three AEP Coal Power Plants Through 2040
by DUANE NICHOLS 15 Oct '21

15 Oct '21

https://www.powermag.com/west-virginia-psc-approves-continued-operation-of-… West Virginia PSC Approves Continued Operation of Three AEP Coal Power Plants Through 2040 From an Article by Aaron Larson, Power Magazine, October 14, 2021 The Public Service Commission of West Virginia (PSC) approved Appalachian Power Co. (APCo) and Wheeling Power Co.’s (WPCo’s) request to keep the 2,930-MW Amos, 1,320-MW Mountaineer, and 780-MW Mitchell coal-fired power plants operational until at least 2040. APCo and WPCo are electric power subsidiaries of American Electric Power Co. (AEP), which is one of the largest generators of electricity in the U.S., owning or operating about 30 GW of generating capacity. AEP is headquartered in Columbus, Ohio, while the principal offices for APCo and WPCo are in Charleston, West Virginia. The three plants are all located in West Virginia. The Amos plant is on the Kanawha River in Putnam County about 15 miles northwest of Charleston; the Mountaineer plant is on the Ohio River in Mason County about 12 miles northeast of Point Pleasant; and the Mitchell plant is on the Ohio River in Marshall County about 12 miles south of Moundsville. The PSC order stems from a filing the companies made in December 2020. APCo requested to obtain the regulatory approvals necessary to implement coal combustion residuals (CCR) and effluent limitation guidelines (ELG) compliance plans, and seek recovery of the estimated $240 million investment for the Amos and Mountaineer plants. Likewise, WPCo requested to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans, and seek recovery of the estimated $132 million investment for the Mitchell Plant. Upgrades Required According to the PSC filing, the bottom ash ponds at each facility are unlined, and would have been required to initiate closure by April 11, 2021, unless an extension was granted by the U.S. Environmental Protection Agency (EPA). In AEP’s most recent financial statements, the company reported filing applications for additional time to develop alternative disposal capacity at the Amos, Mountaineer, and Mitchell plants, among others. The PSC filing also says, “the Mountaineer Plant will be required to address groundwater impacts related to the plant’s existing bottom ash pond. This is currently addressed in accordance with requirements defined in the CCR Rule, known as ‘corrective measures,’ which may entail active treatment of the groundwater.” At the time of the filing, the corrective measures evaluation and selection process was underway, but a final solution had not yet been identified. To continue operating the plants beyond 2028, the companies will be required to close the bottom ash ponds at the Amos, Mountaineer, and Mitchell plants to achieve compliance with the CCR Rule. The schedules for pond closure and developing alternative management options for bottom ash and other wastewaters are site-specific and are subject to approval by the EPA, the filing says. To operate post-2028, the companies will also be required to convert all steam generating units at the Amos, Mountaineer, and Mitchell plants to dry bottom ash handling systems, as well as to install bioreactors for treatment of flue gas desulfurization (FGD) wastewater streams at the Amos and Mitchell plants to comply with the ELG rule. The Mountaineer plant reportedly has a bioreactor in place, which would require only minor upgrades to meet the requirements of the ELG rule. The ELG rule requires that discharge limits be achieved as soon as possible before Dec. 31, 2025, pursuant to a schedule that will be included in the National Pollutant Discharge Elimination System (NPDES) permit for each facility. To expedite compliance, the filing says the companies have developed coordinated compliance activities that would be necessary to address the bottom ash transport water requirements of the ELG rule and the CCR rule. New bioreactors would bring Amos to full ELG compliance by the end of 2022, and Mitchell by April 2025. The upgraded bioreactor at Mountaineer would also bring it into ELG compliance by the end of 2022. Costs and Recovery The PSC said original estimates suggested the impact to residential customers (using 1,000 kWh per month) once the CCR and ELG revenue requirements are totally phased-in upon completion of construction of all the required upgrades would be approximately $2.64 per month. The PSC issued an order on Aug. 4, 2021, that increased the monthly bill of a residential customer using 1,000 kWh per month by approximately $0.38. That rate increment was the first-year phase-in of the impact of the multi-year construction program. The Oct. 13 PSC order will not immediately affect the power bills of West Virginia customers. The rate impact of the full phase-in upon completion of construction, including any additional amount that results from yesterday’s order will require the companies to file a further proceeding to recover the costs of implementing the upgrades, the PSC said. In justifying its decision, the PSC said the estimated cost to West Virginia customers of prematurely retiring the three power plants and replacing their collective generation capacity would be between $1.9 billion and $2.3 billion. Whereas, it said, the estimated total cost to bring all three plants into federal environmental compliance is about $448.3 million. The PSC also said the benefits of the plants’ continued operation to the state’s economy “are considerable,” including direct employment at the plants; use of West Virginia coal; state, county, and local taxes related to operating generation plants; and related employment in businesses supporting the plants and the coal industry. The reliability of fuel-secure baseload generation capacity was also considered by the commissioners in making the decision. Neighboring States Not as Accommodating On Aug. 23, the Virginia State Corporation Commission (SCC) partly denied cost recovery for expenses requested by APCo to comply with the federal ELG rule at the Amos and Mountaineer plants. In that decision, the SCC approved a $27.44 million Virginia revenue requirement for the first year of an environmental rate adjustment clause, which is a rider that recovers expenses from APCo’s Virginia customers associated with federal rules regulating the disposal of coal ash at the two West Virginia plants. However, while the commission moved to approve the recovery of costs related to the CCR rule, it denied about $4.2 million in expenses proposed for projects that would help the plants comply with the ELG rule. Meanwhile, the Kentucky Public Service Commission, in a July 15 order addressing WPCo and Kentucky Power Co.’s (another AEP electric utility subsidiary and co-owner of the Mitchell plant) cost recovery request in that state for the Mitchell plant, likewise approved construction projects to comply with the CCR rule but denied construction projects to comply with ELG requirements. In a statement issued on Wednesday, the PSC of West Virginia said that if Virginia and Kentucky would not share the cost of the upgrades, the two states would not be permitted to use the capacity and energy produced by the plants. For additional background, and more detail on the Kentucky and Virginia filings, see “Regulators Rattle AEP’s Plans to Operate 4.2-GW of Coal Power Through 2040.” —Aaron Larson is POWER’s executive editor (@AaronL_Power, @POWERmagazine).

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proposed “Mountain State Clean Energy” (aka Longview II) natural gas plant,
by DUANE NICHOLS 12 Oct '21

12 Oct '21

Longview is moving forward with plans to construct another (3rd) fossil fueled electric generating station in the Ft. Martin community, about 3 miles from where we live here in the Forks of Cheat Forest. I believe three is too many especially since this so called clean energy plant will emit into the air 321 tons per year of nitrogen oxides (NOx), 210 tons per year of particulate solids, about 25 tons per year of hazardous air pollutants like benzene, toluene, cadmium, chromium, etc., and huge steam plumes continuously. The greenhouse gas (GHG) emissions from the plant will be over 5 million tons per year. The U.S. EPA regards anything over 100,000 tons per year as “significant” as an industrial source. (The truck traffic on Ft. Martin Road is already an extreme challenge for the local residents.) The steam plumes from these plants which we readily see in the sky are primarily water vapor, but these small water droplets absorb acid gases and fine particulate matter emitted from the combustion boilers of all the power plants. These clouds also obscure the sunlight and increase rainout over our area. The finest particles (PM 2.5) are the greatest concern. Also, some chemists have studied free radicals as active chemical species in such environments, too complex for practical resolution. I believe that having three large fossil fuel power plants together here raises air pollution and environment justice issues for the Ft. Martin community, the Bakers Ridge area, University High School, the WVU Medical Center, the Forks of Cheat Forest, and the entire region. The original Ft. Martin plant generates 1100 megawatts of electricity, the Longview coal-fired plant generates 700 MW, and the proposed “clean energy” plant is rated at 1200 MW. So the steam plumes and GHG will be very significant. The concern is for both long term exposures, as some of us are exposed for decades and for short term events such as weather inversions where naturally occurring temperature profiles trap pollutants for hours in specific areas, particularly the valleys. The WV Department of Environmental Protection has published a proposed Air Quality Permit, in the Morgantown Dominion Post on October 1st. I am considering the preparation of a petition for signatures of those who have concerns after reviewing the above information and/or draft Air Quality Permit (Internet link below). See also: https://dep.wv.gov/daq/permitting/Documents/Longview%20PSD/061-00134_APPL_R… >>>>> Duane Nichols, Mon Valley Clean Air Coalition, 304-216-5535 >>>>>> The DAQ has scheduled a public meeting for 6:00 p.m. on Tuesday, October 19, 2021. The public meeting will be held virtually to prevent the spread of COVID-19. Instructions for providing written comments and for providing oral comments at the virtual public meeting are provided below. >>>>>> >>>>>> The purpose of the public review process is to accept public comments on air quality issues relevant to this determination. Only written comments or comments presented orally at the scheduled public meeting will be considered prior to final action on the permit. All such comments will become part of the public record. >>>>>> >>>>>> Written comments must be received by 5:00 p.m. on Monday, November 1, 2021: >>>>>> >>>>>> · Email written comments to Edward.S.Andrews(a)wv.gov with “Mountain State >>>>>> Clean Energy Comments” in the subject line, or >>>>>> >>>>>> · Mail hard copy comments to Edward Andrews, WV Department of Environmental Protection, Division of Air Quality, 601 57th Street, SE, Charleston, WV 25304. >>>>>> >>>>>> Public meeting participation: >>>>>> >>>>>> · To participate online or by telephone, registration is required by 5:00 >>>>>> p.m. on Tuesday, October 19, 2021. To register, please complete the registration >>>>>> form at: https://forms.gle/Cwev9iQPtieG8cU46 >>>>>> >>>>>> To register to speak, please indicate “yes” you want to provide oral comments on the record when you register. A confirmation e-mail will be sent with information on how to join the public meeting. If you do not have internet access and want to register to participate via telephone, please contact Sandie Adkins or Stephanie Hammonds at (304) 926-0475. Registration for the online meeting is required to fulfill the state’s obligation under federal air quality regulations to include a list of >>>>>> participants. Oral comments are limited to 5 minutes. If participating virtually, >>>>>> video demonstrations and screen sharing by commenters is not permitted. >>>>>> >>>>>> Additional information, including copies of the draft permit, application, and all >>>>>> other supporting materials relevant to the permit decision may be obtained by >>>>>> contacting the engineer listed below or downloaded at: >>>>>> >>>>>> https://dep.wv.gov/daq/permitting/Pages/NSR-Permit-Applications.aspx

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Touted as clean, ‘blue’ hydrogen may be worse than gas or coal | Cornell Chronicle
by DUANE NICHOLS 07 Oct '21

07 Oct '21

https://news.cornell.edu/stories/2021/08/touted-clean-blue-hydrogen-may-be-… Touted as clean, ‘blue’ hydrogen may be worse than gas or coal By Blaine Friedlander | August 12, 2021 “Blue” hydrogen – an energy source that involves a process for making hydrogen by using methane in natural gas – is being lauded by many as a clean, green energy to help reduce global warming. But Cornell and Stanford University researchers believe it may harm the climate more than burning fossil fuel. The carbon footprint to create blue hydrogen is more than 20% greater than using either natural gas or coal directly for heat, or about 60% greater than using diesel oil for heat, according to new research published Aug. 12 in Energy Science & Engineering.

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Why Is the Reconciliation Bill Essential for Climate? | Evergreen Action
by DUANE NICHOLS 04 Oct '21

04 Oct '21

Why Is the Reconciliation Bill Essential for Climate? From an Article of the Evergreen Action Blog, September 01, 2021 https://evergreenaction.com/blog/why-is-the-reconciliation-bill-essential-f…

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MVCAC October 2021